Estimating Lost Gas Content for Shales Considering Real Boundary Conditions during the Core Recovery Process

Lingjie Yu; Yuling Tan; Ming Fan; Ershe Xu; Guanglei Cui; Zhejun Pan

doi:10.1021/acsomega.2c02397

Estimating Lost Gas Content for Shales Considering Real Boundary Conditions during the Core Recovery Process

ACS Omega. 2022 Jun 10;7(24):21246-21254. doi: 10.1021/acsomega.2c02397. eCollection 2022 Jun 21.

Authors

Lingjie Yu^{1

2

3}, Yuling Tan^{4

5}, Ming Fan^{1

2

3}, Ershe Xu^{1

2

3}, Guanglei Cui⁶, Zhejun Pan⁷

Affiliations

¹ State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Wuxi 214151, China.
² SINOPEC Key Laboratory of Petroleum Accumulation Mechanism, Wuxi 214151, China.
³ Wuxi Research Institute of Petroleum Geology, SINOPEC, Wuxi 214151, China.
⁴ Department of Engineering Mechanics, Shijiazhuang Tiedao University, Shijiazhuang 050043, China.
⁵ Hebei Key Laboratory of Mechanics of Intelligent Materials and Structures, Shijiazhuang Tiedao University, Shijiazhuang 050043, China.
⁶ Key Laboratory of Ministry of Education on Safe Mining of Deep Metal Mines, Northeastern University, Shenyang 110004, China.
⁷ Key Laboratory of Continental Shale Hydrocarbon Accumulation and Efficient Development, Ministry of Education, Northeast Petroleum University, Daqing, Heilongjiang 163318, China.

Abstract

Shale gas has become an important natural gas resource in recent years as the conventional oil and gas resources are depleting. Shale gas content is one of the most important parameters for reserve calculation and sweet-spot prediction. The traditional core recovery method is widely used to determine gas content. However, the estimation of lost gas content is the main factor of error and difficulty. Large errors and uncertainties occur when using the widely used methods, such as the United States Bureau of Mines (USBM) method. Hence, a more accurate method is required. In this work, a full-process model is developed in COMSOL Multiphysics to describe the lost gas with time during the core recovery process as well as the desorption stage after the core is covered. In this method, by setting the initial gas pressure and flow parameters and matching the desorbed gas volume and considering variable diffusivity with respect to temperature, the initial gas content and the gas lost with respect to time are calculated. Overall, 10 field data are tested using this full-process model, and the USBM method is also applied to compare the results. It is found that if the ratio of lost gas volume estimated using the USBM method to the desorbed gas volume of the field data is lower than 2.0, the USBM method underestimates the lost gas compared to the full-process method; if the ratio is about 2.0, the results from the USBM and the full-process methods are comparable; and if the ratio is close to 3.0, the USBM method tends to overestimate the lost gas. The modeling results indicate that this proposed full-process method is more theoretically sound than the USBM method, which has high uncertainties depending on the number of desorbed gas data points used. Nevertheless, this proposed method requires a large number of parameters, leading to the difficulty in finding true parameters. Therefore, an optimization algorithm is required. In summary, this study provides theoretical support and a mathematical model for the inversion calculation of lost gas during shale core recovery. It is helpful to evaluate the resource potential and development economics of shale gas more accurately.